WTI Crude is back below $45 again this morning - pressing towards 2015 and cycle lows -after Goldman Sachs' Jeffrey Currie warns 'lower for longer' is here to stay, with price risk "substantially skewed to the downside." His reasoning are manifold, as detailed below, but overarching is oversupply (Saudi Arabia has a challenge in Asia as it battles to maintain mkt share, the Russians are coming, andother OPEC members want a bigger slice) and, even more crucially, storage is running out. As Currie concludes, this time it is different. Financial metrics for the oil industry are far worse.
As Goldman Sachs' Jeffrey Currie explains...
1)Although spot oil prices have only retraced to the lows of this winter, forward oil prices, commodity currencies and energy equities/credit (relative to the broad indices) have now all retraced to levels not seen since 2005, erasing a decade of gains. This creates a very different economic environment as the search for a new equilibrium resumes: financial stress is higher, operational stress as defined below is more extreme and costs have declined further due to more productivity gains, a substantially stronger dollar and sharp declines in other commodity prices. These differences reflect not only a further deterioration in fundamentals, but also the financial markets’ decreasing confidence in a quick rebound in prices and a recognition that the rebalancing of supply and demand will likely prove to be far more difficult than what was previously priced into the market. This is all in line with our lower-for-longer view. While we maintain our near-term WTI target of $45/bbl, we want to emphasize that the risks remain substantially skewed to the downside, particularly as we enter the shoulder months this autumn.
2) In January, we argued that one of the key tenets of the New Oil Order was that capital is now the new margin of adjustment. As shale has dramatically reduced time-to-build (the time between when producers commit capital and when they get production) from several years to several months, oil prices now need to remain lower for longer to keep capital sidelined and allow the rebalancing process to occur uninterrupted. This spring’s rally in prices did prove to be self-defeating. Not only did all the capital markets reopen as oil prices rose, but producers began to redeploy rigs and remained under hedged, which is a reflection that the industry simply had not faced enough pain to create real financial stress that would create change.
3)This time it is different. Financial metrics for the oil industry are far worse. Forward oil prices are c.10% lower (at $58/bbl the 3-year forward oil price is at its lowest in a decade). At the same time leverage for the industry is rising as hedge books are much lighter, with 2016 hedge ratios at 9% versus a five-year average of 25%. Energy equity markets relative to the equity indices are at the lowest level since 2005 and at 3-year lows on an absolute basis. Energy high yield as an OAS spread ratio has also pushed above December 2014 highs. Although financial stress is higher, it alone is still unlikely to create the rebalancing needed due to the unique market structure of the New Oil Order, sidelined capital and declining costs.
4) The market structure of the New Oil Order is unprecedented. In January we showed that high-quality producing assets were on average owned by weak balance sheets while strong balance sheets on average owned the lower-quality producing assets. In other words, the IOCs and some NOCs own most of the higher-cost production while E&Ps, particularly US E&Ps, own much of the lower-cost production. Historically, weak balance sheets typically owned high-cost assets and vice versa, creating a linear relationship between lower prices and financial stress, which historically led to more financially motivated supply cuts as prices dropped. Yes, we have seen some of the few companies with weak balance sheets and high-cost assets run into trouble and go into maintenance mode, but they are not sufficient to shift the market balance. In contrast, the weaker balance sheets with high-quality assets issued equity during the spring, when capital markets were open, to buy more longevity by reducing leverage by half a turn. On net, from a financial perspective, the adjustment process is now likely to take longer.
5) Logistical and storage constraints are also tighter this time. We have argued for decades now that modern energy markets mostly rebalance through operational stress. Operational stress is created when a surplus breaches logistical or storage capacity such that supply can no longer remain above demand. Although perceptions this past April were that the market was near operational stress, it is now far closer. We estimate that the industry has added c.170 million barrels of petroleum to crude and product storage tanks since January and c.50 million barrels to clean and dirty floating storage. With increased operational stress in the system versus six months ago, we now attach a substantially higher probability to this being the margin of adjustment than we did in January. While the probability of blowing out storage this autumn is higher, the market will need to balance or adjust before next spring’s turnarounds.
6) Should the market breach logistical and storage capacity constraints, this would kill the storage arbitrage between spot and forward prices and create a significant flattening of the entire forward curve (though front timespreads would likely blowout initially). Historically, once storage capacity is breached across all crude and products, supply must be brought back below demand immediately. To create the rebalancing physical constraints create a collapse in spot prices below cash costs as supply is forced in line with demand (late 1998 is a good example), creating the birth of a new bull market. Breaching crude storage capacity alone is not sufficient, as it simply leads to an increase in refinery runs creating product where storage capacity is available, so both crude and product storage needs to be breached. Further, this only requires breaching capacity in one or two of the key product markets given constraints on refinery product yields. In the current market, the likely candidate is distillate as inventories, particularly outside of the US, are extremely high and margins are weak. As the curve flattens, long-dated oil prices historically have drifted down toward cash prices. As producers face increasing financial stress, covering operating costs and surviving becomes more important than future growth.
7) It is important to separate cash costs from total costs. As oil markets are substantially oversupplied by nearly every measure (see below), the need for new incremental capacity is limited at the margin. New incremental capacity requires prices above ‘total’ costs, defined as fixed (capex) plus variable/cash costs (opex). However, in an environment where the market only needs to produce from existing capacity, prices only need to cover variable/cash costs to keep existing capacity operating. And herein lies the paradox, for the high-cost, strong balance sheet producer, cash costs are $40-$45/bbl versus total costs closer to $75/bbl. In contrast, the low-cost, weak balance sheet producer faces cash costs near $20/bbl with total costs near $55/bbl. As the high-cost production is mostly oil sands and other costly to shut in conventional oil, the stronger balance sheet producers with this production will resist the costs of shutting in, leaving the easier-to-shut, lower-cost production held by the weaker balance sheets as the more likely candidate. This suggests the volatility and risks to the downside are significant. Furthermore, a stronger US dollar, productivity gains and other commodity price declines only creates more cost deflation, via the negative feedback loop, making cash costs a moving target to the downside.
8) Commodity and emerging market currencies have also erased a decade of gains, reflecting the significant macroeconomic imbalances many of these countries are facing, created in part by the sharp decline in all commodity prices. This not only impacts emerging market demand for oil, Latin American demand in particular, but also lowers the costs to produce oil and commodities in these countries. To illustrate the sensitivity of oil cash costs to the Brazilian real (BRL) and Canadian dollar (CAD), we find that a 10% move in BRL or CAD shifts cash costs by 3% and 5% respectively. The BRL and CAD have weakened year-to-date by 31% and 14% respectively. Further, as we argued late last year, 2015 supply growth in regions facing sharp currency depreciation have been revised up since March by the IEA: Brazil (+24 kb/d), North Sea (+65 kb/d) and Russia (+145 kb/d). It is important to emphasize that markets have never seen such a large appreciation in the US dollar at the same time they have seen such a large surplus in the oil market. While it is unprecedented in the current direction, the weakest US dollar ever recorded on a trade-weighted basis was when oil prices peaked above $147/bbl in July 2008. As we have emphasized in all of our research since 2013, it is the same macro forces working in reverse today that pushed markets to the highs during the previous decade. The crude market didn’t go to $147/bbl on oil fundamentals alone, nor would it be collapsing like this on oil fundamentals alone.
9) Nonetheless, fundamentals are weaker today than in 1Q. Global supply is currently up 3.0 million b/d (and averaged up 3.2 million b/d over the past 12 months), driven in large part by a surge in low-cost production from Saudi Arabia, Iraq and Russia. The largest demand growth ever observed was in 2004 when China and the emerging markets kicked off the previous decade's commodity boom and drove a 3.15 million b/d demand growth number. In 2004 the emerging markets had clean balance sheets in strengthening currencies which reflected their good health. Today, that boom decade has been brought to a halt. These countries are facing large macro imbalances and debt. Not only has emerging market growth slowed, but any benefits from lower prices are mostly behind us now, as the benefits only last 6 to 9 months. We estimate that current oversupply is c.2.0 million b/d versus c.1.8 million b/d in 1H15.
10) The oil industry on average is not earning its cost of capital. The distinction between cash costs and total costs, also applies to ‘well’ versus ‘company’ returns. While the returns at the well can be economical at prices near $50/bbl, the returns for the company can be deeply underwater due to large-scale investments when prices were at $100/bbl. Even assuming an aggressive company decline rate of 25% over the past year, that would make 75% of the assets legacy production. While commodity markets don’t care about legacy fixed costs, and only about today’s cost to bring on a marginal barrel, potential equity and credit investors do care about those legacy costs and what they do to company long-run returns. In general, energy companies at present cannot earn their cost of capital over the long-term (defined as the past 50 years). Long-run returns are 10% versus a cost of capital of 12.5%. In other words, they are wealth-destroying propositions from the get go. The reason for this is the industry constantly invests in new capacity during the investment phase of the super cycle, i.e. high and rising prices, and brings on line this new capacity during the exploitation phase of the super cycle, i.e. low and declining prices.
11) While the supply and demand for the barrels of oil will likely find a balance between now and sometime in 2016 with an increasing likelihood of this being driven by operational stress, this doesn’t mean a sharp rebound in prices will occur quickly as so many other factors will likely weigh on prices. Not only will the macro forces keep prices under pressure, but historically markets trade near cash costs until new incremental higher-cost capacity is needed (even the IEA has revised 2015 non-OPEC output growth from existing capacity up by 265 kb/d since March). In addition, low-cost OPEC producers are likely to expand capacity now that they have pushed output to near max utilization. At the same time Iran has the potential to add 200 to 400 kb/d of production in 2016 and with significant investment far greater low-cost volumes in 2017 and beyond. Iran, like other OPEC countries, needs the revenues through volume. Even Venezuela accepted another $5 billion last week from China to produce oil from older fields. Finally, the capital markets for energy need to be rebalanced through consolidation and capital restructuring. This takes time to achieve. In the previous cycle this took from 1986 to 1998 and ended with the creation of the super majors. Today we expect it to go more quickly, just as we erased a decade in the matter of months, but it will take time.